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Collaborating Authors
Clemens, Torsten
The Role of Diffusion on Reservoir Performance in Underground Hydrogen Storage
Arekhov, Vladislav (OMV Exploration & Production GmbH (Corresponding author)) | Clemens, Torsten (OMV Exploration & Production GmbH) | Wegner, Jonas (HOT Microfluidics GmbH) | Abdelmoula, Mohamed (HOT Microfluidics GmbH) | Manai, Taoufik (Schlumberger)
Summary Underground hydrogen storage (UHS) has the potential to balance fluctuating sustainable energy generation and energy demand by offering large-scale seasonal energy storage. Depleted natural gas fields or underground gas storage fields are attractive for UHS as they might allow for cost-efficient hydrogen storage. The amount of cushion gas required and the purity of the backproduced hydrogen are important cost factors in UHS. This study focuses on the role of molecular diffusion within the reservoir during UHS. Although previous research has investigated various topics of UHS such as microbial activity, UHS operations, and gas mixing, the effects of diffusion within the reservoir have not been studied in detail. To evaluate the composition of the gas produced during UHS, numerical simulation was used here. The hydrogen recovery factor and methane-to-hydrogen production ratio for cases with and without diffusive mass flux were compared. A sensitivity analysis was carried out to identify important factors for UHS, including permeability contrast, vertical-to-horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure-dependent diffusion. Additionally, the effect of numerical dispersion on the results was evaluated. The simulations demonstrate that diffusion plays an important role in hydrogen storage in depleted gas reservoirs or underground gas storage fields. Ignoring molecular diffusion can lead to the overestimation of the hydrogen recovery factor by up to 9% during the first production cycle and underestimation of the onset of methane contamination by half of the back production cycle. For UHS operations, both the composition and amount of hydrogen are important to design facilities and determine the economics of UHS, and hence diffusion should be evaluated in UHS simulation studies.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
Summary If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backproduced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.
- Asia (0.93)
- Europe > Austria (0.68)
- North America > United States > Michigan (0.28)
- Geology > Rock Type (0.88)
- Geology > Geological Subdiscipline (0.66)
Performance of Inflow Control Devices (ICDs) in Horizontal Injection Wells with Injection Induced Fractures
Hu, Jinchuan (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, U.S.A.) | Ou, Yuhao (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, U.S.A.) | Zheng, Shuang (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, U.S.A.) | Sharma, Mukul (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, U.S.A.) | Clemens, Torsten (OMV, Vienna, Austria) | Chiotoroiu, Maria M. (OMV, Vienna, Austria)
Abstract Inflow Control Devices (ICDs) have been extensively used in injection wells to control the injection profile. The design of ICDs is usually based on the permeability and thickness of each injection zone. The primary objectives of this paper are to (a) study the influence of ICDs on the initiation and propagation of injection induced fractures (IIFs), (b) to demonstrate the importance of injection induced fractures on the design and placement of ICDs in horizontal injectors. A fully coupled reservoir-fracture-wellbore simulator is applied to study the performance of injectors with ICDs. The simulator implicitly couples the performance of the ICDs with multi-phase flow in the reservoir, solid mechanics, thermal effects and allows for fracture propagation and particle plugging. The stress field in the reservoir accounts for thermo-poro-elastic effects during cold water injection. Fracture initiation and propagation induced by both internal and external filtration and thermal effects are simulated. The ICD pressure drop is implicitly solved in the fully coupled non-linear system of equations using a Newton-Raphson method. This allows us to predict fracture initiation and growth in different sections of the well over time. The impact of ICD placement and characteristics can be clearly evaluated by the model. It is shown that the growth of injection induced fractures plays a dominant role in the performance of the ICDs and controls the injection flow profile. The flow distribution without ICDs can vary significantly with time due to injection induced fracture growth. Injector performance is evaluated for different ICD arrangements. The ICDs are shown to effectively control the flow distribution along the wellbore for better conformance control. If properly designed, ICDs can help to minimize the impact of potential "thief" fractured zones. While ICDs reduce injectivity by creating an additional pressure drop, the flow is much more evenly distributed, and this can help to slow down the injectivity decline, improve reservoir sweep and oil recovery. The results show that, in most cases, more ICDs and specific ICD arrangements can improve the injection profile to increase the recovery and decrease the risk of out zone fracture growth. This paper presents a method to study the influence of ICDs and injection induced fractures on water injector performance using a fully coupled reservoir-fracture-wellbore model. The model, for the first time, presents results showing the dynamics of growth of multiple fractures in segments of the injector wellbore separated by ICDs and the impact they have on the flow distribution in the well. These results form the basis for the design and placement of ICDs in horizontal injectors.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
Abstract If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the back-produced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in literature. Thus, laboratory measurements were performed to improve storage performance predictions for an Underground Hydrogen Storage (UHS) project in Austria. A high-pressure-high-temperature experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of back-produced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients which impacts UHS performance
- North America > United States (1.00)
- Europe > Austria (0.68)
- Geology > Rock Type (0.88)
- Geology > Geological Subdiscipline (0.66)
Abstract Underground Hydrogen Storage (UHS) allows the storage of energy that is generated by fluctuating renewable energy sources such as solar and wind. Depleted hydrocarbon fields can be used to store hydrogen. The remaining hydrocarbon gas can be used as cushion gas. To engineer the UHS process, accurate phase, volumetric and transport behavior ("PVT") of hydrogen-hydrocarbon mixtures is required. In this paper, we develop an EOS and viscosity model to describe the operating envelope of a UHS operation in Austria. Constant Composition Expansion (CCE) experiments were performed using a customized visual HPHT PVT set-up minimizing volume and density errors to ensure high accuracy of the measurements involving hydrogen. Viscosity experiments were performed using a capillary rheometer. Both experimental setups show a total measurement uncertainty of less than 2%. Experiments were performed for various hydrogen- hydrocarbon mixtures to cover the full range of the depleted gas field which is considered. The composition of hydrocarbon-hydrogen mixtures was confirmed using gas chromatography. The results were used to develop an EOS for the hydrogen-hydrocarbon system and to "tune" reduced density corresponding state models to match measured viscosity data. The measured PVT and viscosity data of hydrogen-hydrocarbon mixtures measured in this study deviate somewhat from the default fluid models used in most commercial simulators. In this paper, a fluid model was developed using the Peng-Robinson EOS with volume shifts, and a reduced density corresponding state LBC viscosity model [1]. The fluid model was matched to (1) hydrogen-hydrocarbon gas laboratory measurements presented in this paper, (2) measured hydrogen-methane binary data (density and viscosity) taken from the literature, and (3) REFPROP (NIST) [2] calculated density and viscosity data for the hydrogen-hydrocarbon gas, hydrogen-methane binary system, and pure components. The required alteration (tuning) of the parameters in the fluid model development is discussed. The impact of hydrogen content on gas mixture viscosity is studied based on a large number of literature studies for the hydrogen-methane binary system, and the hydrogen-hydrocarbon gas system presented in this paper for relevant operating conditions. Some literature data for hydrogen-methane systems show an anomalous, near-constant gas viscosity behavior at constant pressure and temperature with increasing hydrogen content, until a critical hydrogen content is reached (>50 mole%). Similar behavior is also seen in the hydrogen-hydrocarbon gas mixture presented in this paper.
The Role of Diffusion on the Reservoir Performance in Underground Hydrogen Storage
Arekhov, Vladislav (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Wegner, Jonas (HOT Microfluidics GmbH) | Abdelmoula, Mohamed (HOT Microfluidics GmbH) | Manai, Taoufik (Schlumberger)
Abstract For large scale seasonal storage, Underground Hydrogen Storage (UHS) can be used to balance fluctuating sustainable energy generation and energy demand. Similar to underground natural gas storage, depleted gas fields potentially allow for cost-efficient hydrogen storage. One of the major cost factors in UHS is the amount of cushion gas required and the purity of the hydrogen produced during the production cycle. The hydrocarbon gas remaining in the reservoir can be used as cushion gas to significantly reduce UHS costs. To evaluate the composition of the gas produced during the production cycle of UHS, numerical simulation was applied. One of the important processes in UHS is molecular diffusion within the reservoir. The hydrogen recovery factor and methane to hydrogen production ratio were compared for cases with and without diffusive mass flux. Furthermore, a sensitivity analysis was carried out to identify important factors for UHS. The following parameters were investigated: permeability contrast, vertical to horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure dependent diffusion. In addition, the effects of numerical dispersion on the results were evaluated and are discussed. The results of numerical simulation show the importance of diffusion on hydrogen storage in depleted gas reservoirs. Molecular diffusion plays a major role in case of heterogeneous reservoirs and large permeability contrasts. In low permeability zones, the diffusive mass transport becomes dominant over advective flux. Hydrogen propagates further into the low permeable layers of the reservoir when diffusion effects are considered compared with the cases neglecting diffusion. Similar effects are observed during the production cycle. Hydrocarbon gas in low permeability zones becomes more mobile due to diffusive transport. Thus, a larger amount of methane is back-produced with hydrogen for the cases when diffusion is simulated. It is shown that if molecular diffusion is ignored, the hydrogen recovery factor can be overestimated by up to 9% during the first production cycle and the onset of methane contamination can be underestimated by half of the back production cycle. Simulating pressure dependent diffusion might be important for specific configurations and should be covered in a sensitivity. The results show that molecular diffusion within the reservoir has an impact on the onset of methane contamination when hydrocarbon gas is used as cushion gas in UHS. Also, the total amount of hydrogen produced is overestimated. For UHS operations, both, the composition and amount of hydrogen is important to design facilities and to determine the economics of UHS and hence diffusion should be evaluated in UHS simulation studies.
- Europe > Austria (0.29)
- North America > United States (0.28)
Abstract District heating can be decarbonized by using low enthalpy geothermal heat. In this case study, water from a deep saline aquifer with a temperature of 90-110 °C is produced, heat extracted for district heating and the cold water re-injected into the aquifer. There are substantial subsurface uncertainties in the structure as well as porosity and permeability distribution of the saline aquifer that need to be addressed to optimize heat extraction under uncertainty. The deep saline aquifer characterization is based on 3D seismic and a limited number of wells. Hence, substantial uncertainty exists in porosity/permeability distribution and dynamic and thermal properties. To address the uncertainty, different geological concepts need to be evaluated and parameter ranges for geostatistical and poro-perm relationships need to be used. To cover the uncertainty range, we constructed 600 geological models all honoring the limited existing data. However, dynamically simulating all the geological models including the ranges for the thermal properties is usually too costly. We utilize a geo-screening workflow, which selects a subset of representative models based on dynamic (proxy) response, the workflow aims at keeping the same variability of the subset as for the full ensemble. This is achieved via a dimensionality reduction of the problem, by clustering of the models in multi-dimensional space. The centroids of these clusters are selected as representative models used for full-physics simulations to forecast heat extraction under uncertainty. To define a consistent method for selecting a representative subset of geologic realization we simulated the full ensemble and compared it to (i) subsets of different clustering approaches using static (heat in-place) and dynamic (tracer rate & flux pattern) proxy responses and (ii) subset sizes. The results of the workflow show that the tracer rate is a better metric for the selection of the cluster centroids compared with flux-pattern and in particular heat in place. For this case 20-40 geological realizations were sufficient to cover the uncertainty space for forecasting low enthalpy heat extraction. The suggested workflow allows for addressing the subsurface uncertainty in static and dynamic parameters making use of streamline simulation to reduce simulation costs. The resulting model ensemble can be used for field development planning of low enthalpy heat extraction under uncertainty.
- North America > United States (0.68)
- Asia > Indonesia (0.46)
- Europe > Austria > Vienna (0.31)
- Geology > Rock Type > Sedimentary Rock (0.93)
- Geology > Geological Subdiscipline (0.93)
- Geology > Sedimentary Geology > Depositional Environment (0.93)
- Geology > Structural Geology (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.93)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
- Asia > Indonesia > Java > Dieng Field (0.99)
Improving Alkali Polymer Flooding Economics by Capitalizing on Polymer Solution Property Evolution at High pH
Nurmi, Leena (Kemira Oyj) | Hincapie, Rafael E. (OMV Exploration & Production GmbH (Corresponding author)) | Clemens, Torsten (OMV Exploration & Production GmbH) | Hanski, Sirkku (Kemira Oyj) | Borovina, Ante (OMV Exploration & Production GmbH) | Födisch, Hendrik (Kemira Oyj) | Janczak, Alyssia (OMV Exploration & Production GmbH)
Summary Alkali polymer (AP) flooding is a promising enhanced oil recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allow for cost reduction and increase in injectivity and incremental oil recovery for AP projects. The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single-/two-phase corefloods with aged and nonaged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension (IFT) were measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperatures. The accelerated method developed earlier for neutral pH range provides a possibility to run aging at elevated temperatures in a short time frame and transfer the data to reservoir temperature to give information on the long-term performance. The transfer takes place through a conversion factor derived from the first-order kinetics of acrylamide hydrolysis in pH 6–8. In the present work, the applicability of the accelerated method is evaluated for elevated pH by determining the degree of polymer hydrolysis over time via nuclear magnetic resonance and linking it to viscosity performance at various temperatures. The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested hydrolyzed polyacrylamide (HPAM) by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in a polymer solution viscosity of 160% compared with initial conditions within days at a reservoir temperature of 49°C, after which the viscosity leveled off. Accelerated aging experiments at higher temperatures predict long-term stability of the increased viscosity level for several years. Single-phase injection test in a representative core confirmed the performance of the aged solution compared to a nonaged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions, 19 vs. 48 µg/g in the static adsorption test, respectively. Two-phase coreflood tests showed increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and nonaged polymer solution was similar, confirming the potential for cost savings using lower polymer concentration. This is leading to an improved injectivity and makes use of the increased polymer viscosity down in the reservoir through hydrolysis. The current work combines multiple aspects that should be considered in the proper planning of AP projects—not only improvements in polymer viscosity performance due to water softening but also long-term effects due to increased pH. Additionally, these aspects are combined with changes in adsorption properties. The results show that the design of AP projects will benefit from the holistic approach and understanding the changes in polymer rheology with time. The costs of AP projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of AP projects takes good injectivity of nonaged polymers and the aging of the polymer solutions in alkali into account. Overall, we aim to reduce the polymer concentration—which is a key cost driver—compared with a nonaged application. We show that for AP effects, these effects should be evaluated to improve the economics.
- Europe > Austria > Vienna (0.28)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (3 more...)
Synergies of Alkali and Polymers - Decreasing Polymer Costs and Increasing Efficiency
Hincapie, Rafael E. (OMV Exploration & Production GmbH) | Borovina, Ante (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Hoffmann, Eugen (HOT Microfluidics GmbH) | Tahir, Muhammad (HOT Microfluidics GmbH) | Nurmi, Leena (Kemira Oyj) | Foedisch, Hendrik (Kemira Oyj) | Hanski, Sirkku (Kemira Oyj) | Wegner, Jonas (HOT Microfluidics GmbH) | Janczak, Alyssia (OMV Exploration & Production GmbH)
Abstract Alkali injection leads to in-situ soap generation of high TAN number oil and residual oil reduction accordingly. We are showing that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to "aging" of the polymers at high pH. Furthermore, AP conditions enable reducing polymer retention in the reservoir decreasing the Utility Factors (kg polymers injected / incremental bbl. produced). Phase behavior tests were performed to understand the oil/alkali solution interaction and interfacial tension (IFT) was measured. Micromodel floods addressed displacement effects while two-phase core floods covered the displacement efficiency of alkali polymer solutions. We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions. IFT measurements showed that saponification (41 μmol_g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. Alkali phase experiments confirmed that emulsions are formed initially and supported the potential for residual oil mobilization. Aging experiments revealed that the polymer hydrolysis rate is substantially increased at high pH compared to polymer hydrolysis at neutral pH resulting in 60 % viscosity increase in AP conditions. Within the reservoir, the fast aging of polymer solutions in high pH results in increase to target viscosity while maintaining low adsorption owing to alkali and softened water. Hence, injectivity of alkali polymer solutions can be improved over conventional polymer flooding. The two-phase experiments confirmed that lower concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, less polymers are consumed than in conventional polymer floods significantly decreasing the Utility Factor (injected polymers kg/incremental bbl. produced). Overall, the work shows that Alkali/Polymer (AP) injection leads to substantial incremental oil production of reactive oils. A workflow is presented to optimize AP projects including near-wellbore and reservoir effects. AP flood displacement efficiency must be evaluated incorporating aging of polymer solutions. Significant cost savings and increasing efficiency can be realized in AP floods by incorporating aging of polymers and taking the reduced polymer adsorption into account.
- Europe (1.00)
- North America > United States (0.93)
- Asia > Middle East (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- (4 more...)
Improving Alkali Polymer Flooding Economics by Capitalizing on Polymer Solution Property Evolution at High pH
Födisch, Hendrik (Kemira Oyj) | Nurmi, Leena (Kemira Oyj) | Hincapie R., Rafael E. (OMV Exploration & Production GmbH) | Borovina, Ante (OMV Exploration & Production GmbH) | Hanski, Sirkku (Kemira Oyj) | Clemens, Torsten (OMV Exploration & Production GmbH) | Janczak, Alyssia (OMV Exploration & Production GmbH)
Abstract Alkali Polymer (AP) flooding is a promising Enhanced Oil Recovery (EOR) method to increase oil recovery from reactive oils. It is essential to carefully select the alkali and polymer type and concentration to optimize incremental oil recovery. In addition to the conventional laboratory tests for polymer flooding, the effects of the high pH on the polymer and its evolving properties over time need to be investigated. Consideration of near-wellbore and reservoir effects is a key in designing the process. We are showing how understanding and taking advantage of the polymer performance in a high pH environment allows to reduce costs, increase injectivity and incremental oil recovery for AP projects. The polymer performance was evaluated for AP flooding of the Matzen field (Austria). Evaluations included changes in polymer rheology during aging at high pH conditions, phase behavior tests, and single/two-phase core floods with aged and non-aged polymer solutions. In addition, adsorption of the aged polymer and interfacial tension was measured. The aging was studied in anaerobic conditions at reservoir temperature and through an accelerated method at elevated temperature. The degree of polymer hydrolysis over time was determined via NMR and linked to viscosity performance. The AP conditions in the Matzen AP flooding project (pH > 10) lead to an increased initial rate of polymer hydrolysis of the tested HPAM by a factor of 100 compared to hydrolysis at a neutral pH level. This resulted in a rapid increase in polymer solution viscosity of 160 % compared with initial conditions within days at reservoir temperature of 49 °C, after which the increase leveled off. Accelerated aging experiments at higher temperature predict long-term stability of the increased viscosity level for several years. Single-phase injection test in representative core confirmed the performance of the aged solution compared to a non-aged solution at the same polymer concentration. The retention of polymers is reduced in AP conditions compared with traditional neutral pH conditions. Two-phase core flood tests showed the increased polymer viscosity at reservoir conditions. The displacement efficiency of the aged and non-aged polymer solution was similar confirming the potential for cost savings using lower polymer concentration and making use of the increased polymer viscosity owing to hydrolysis. The results show that the design of alkali polymer projects needs to take the changing polymer rheology with time into account. The costs of alkali polymer projects can be reduced owing to the lower required polymer concentrations for the same displacement efficiency and reduced retention of polymer. An efficient design of alkali polymer projects takes good injectivity of non-aged polymers and the aging of the polymer solutions in alkali into account.
- Europe > Austria > Vienna (0.28)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (3 more...)